This invention relates to the analysis of a gas stream which includes steam, such as that released during the drilling of a geothermal well, or from a steam power plant.
Geothermal energy is recovered by producing steam or hot water from underground reservoirs. The hot fluids are normally recovered by drilling a well sufficiently deep to penetrate the fluid-bearing portion of the reservoir. During the drilling operations, conventional drilling fluids are used to carry cuttings from the well bore. Ordinarily, the upper portion of the well is drilled with conventional drilling mud until the well nears the fluid-bearing portion of the reservoir. Thereafter, the well is drilled with compressed air as the drilling fluid to avoid plugging the formation from which steam or hot water is to be produced. Ideally, the producing formation is penetrated by the well under controlled blowout conditions, i.e., the pressure in the well bore bore is kept slightly below that of the fluids in the reservoir, so that net flow of fluids is from the reservoir into the well bore. Thus, the injected air and the fluids produced from the reservoir carry the formation cuttings to the surface. As the fluids approach the surface, reduced pressure usually results in the hot liquid water flashing to steam, if it was not already in that form. The steam, formation cuttings, and returning air are usually passed through a separator which removes the particulate matter from the stream of air and steam. Thereafter, the air and steam are discharged to the atmosphere.
Geothermal steam usually contains hydrogen sulfide gas, which is an odorous pollutant. Consequently, the emission of untreated geothermal steam to the atmosphere is undesirable, and is usually limited by environmental regulations.
Initially, regulatory agencies attempted to control geothermal emission of hydrogen sulfide by establishing emission for an entire geothermal field. Because of the variability of hydrogen sulfide emissions from individual wells, and because of the relatively large number of operators involved in geothermal exploration and production, the control of emission by geothermal field proved impractical. Accordingly, individual wells are now monitored for hydrogen sulfide during drilling and testing, and abatement procedures are put into effect as required. For example, some new regulations require that the air pollution not exceed 2.5 kilograms of hydrogen sulfide per hour per well.
Although geothermal well drilling is only a minor, transitory source of hydrogen sulfide emission, the hourly emission standards can be exceeded for short periods of time. Emissions from steam power plants are also a potential source of hydrogen sulfide, if the steam used by the plants has not been properly treated. Such emissions can be controlled by down-hole injections of ammonia or by blooie line injection of aqueous hydrogen peroxide and sodium hydroxide solutions into the stream of steam and hydrogen sulfide, as disclosed in U.S. Pat. No. 4,151,260, issued Apr. 24, 1979, to Woertz. It is important, therefore, to monitor accurately the hydrogen sulfide concentration in gaseous streams from wells and power plants to assure compliance with emission regulations, and to determine the optimum hydrogen sulfide abatement procedures.
In the past, hydrogen sulfide produced from a geothermal well has been determined by removing a bulk sample from the stream of gas flowing from the well, removing solids, condensing the steam in the sample, and thereafter analyzing the residual gas. We have found that the condensation of steam introduces serious errors into the analysis for hydrogen sulfide. First, hydrogen sulfide is absorbed by the condensed steam, which cause a reduction in the observed concentration of hydrogen sulfide. An offsetting problem is that concentration of hydrogen sulfide observed in the vapor phase remaining after condensation of the steam depends upon the solubility and partial pressure of hydrogen sulfide in the condensate at various temperatures along the sample line. This could cause excessively high or low readings at the analyzer. For example, the lowering of the condensate temperature reduces the amount of hydrogen sulfide in the vapor phase at equilibrium conditions. A change of 10.degree. C. can change the observed hydrogen sulfide concentration by 40% or more. Such changes can occur due to variable weather or operating conditions and, therefore, introduce serious error in the analysis. Moreover, changes in the percent of noncondensibles, the flow rate of the drilling air, and the pH of the condensate affect the observed concentration of hydrogen sulfide.
This invention provides an apparatus and method for taking and analyzing a representative sample of a gas stream of steam and other gases free of the errors referred to above.